For thin-oil-rim reservoirs, well placement, well type, well path, and the completion methods must be evaluated with close integration of key reservoir and production-engineering considerations. For thin-oil-rim reservoirs, well placement, type and path, and well-completion methods, should be evaluated with close integration of key reservoir- and production-engineering considerations.
This course is intended for those who are very familiar with reservoir evaluation and development concepts for conventional reservoirs but who are interested in learning more about the unique technologies applied to shale and tight reservoirs. Recent success in developing oil from very low permeability reservoirs in North America has sparked global interest in how these plays are being identified, evaluated and developed. This course addresses these issues that require unique approaches, as compared to conventional oil reservoirs, primarily in the areas of well design, hydraulic fracture design, log analysis, core analysis and production forecasting. This course is intended for engineers, geologists, and technical support staff. All cancellations must be received no later than 14 days prior to the course start date.
Africa (Sub-Sahara) Eni started production from the Nené Marine field, which sits in the Marine XII block in 28 m of water, 17 km offshore the Republic of the Congo. The first phase of the field produces from the Djeno pre-salt formation, 2.5 km below the ocean floor at a rate of 7,500 BOEPD. Future development will take place in several stages and will involve the installation of more production platforms and the drilling of at least 30 wells. Eni (65%) is the operator with partners New Age (25%), and Société Nationale des Pétroles du Congo (10%). The well's primary target is the Bunian structure: a four-way, fault-bounded anticline, which was defined by a 3D seismic survey. It will be drilled to a total depth of 1682 m.
Africa (Sub-Sahara) Bowleven began drilling operations at its Zingana exploration well on the Bomono permit in Cameroon. Located 20 km northwest of Douala, Cameroon's largest city, the well will target a Paleocene (Tertiary) aged, three-way dip closed fault block. The company plans to drill the well to a depth of 2000 m and will then spud a second well in Moambe, 2 km east of Zingana. Bowleven is the operator and holds 100% interest in the license. Asia Pacific China National Offshore Oil Company (CNOOC) has brought its Dongfang 1-1 gas field Phase I adjustment project on line ahead of schedule. The field is located in the Yinggehai basin of the Beibu Gulf in the South China Sea and has an average water depth of 70 m. The field is currently producing 53 MMcf/D of gas and is expected to reach its peak production of 54 MMcf/D before the end of the year.
Identification of a prospect is normally done based on seismic interpretation and geological understanding of the area. However, due to the inherent uncertainties of the data we still observe in many cases that all key petroleum system elements are present, but still the drilled prospect is dry. Such failures are mostly attributed to a lack of understanding of seal capacity, reservoir heterogeneity, source rock presence and maturation, hydrocarbon migration, and relative timing of these processes. The workflow described in this paper aims to improve discovery success rates by deploying a more rigorous and structured approach. It is guided by the play-based exploration risk assessment process. The starting point is always that the process is guided by the the basic understanding of a mature kitchen should always be based on a regional scale petroleum systems model. However, while evaluating prospects, the migration and entrapment component of a prospect should always be investigated by means of a locally refined grid-based petroleum system model. The uniquepart of this approach is the construction of a high-resolution static model covering the prospects, which is built by using available well data, seismo-geological trends and attributes to capture reservoir potential. Additional inputs such as fault seal analysis also helps to understand prospect scale migration and associated geological risks. In the regional play and local prospect-scale petroleum system models, geological and geophysical inputs are utilized to create the uncertainty distribution for each input parameter which is required for assessing the success case volume of identified prospects. The evaluated risk is combined with the volumetric uncertainty in a probabilistic way to derive the risked volumetrics. It is further translated into an economic evaluation of the prospect by integrating inputs like estimated production profiles, appropriate fiscal models, HC price decks, etc. This enables the economic viability of the prospects to be assessed, resulting in a portfolio with proper ranking to build a decision-tree leading to execution and operations in ensuing drilling campaigns.
Ibrahim Mohamed, Mohamed (Colorado School of Mines) | Salah, Mohamed (Khalda Petroleum) | Coskuner, Yakup (Colorado School of Mines) | Ibrahim, Mazher (Apache Corp.) | Pieprzica, Chester (Apache Corp.) | Ozkan, Erdal (Colorado School of Mines)
A fracability model integrating the rock elastic properties, fracture toughness and confining pressure is presented in this paper. Tensile and compressive strength tests are conducted to define the rock-strength. Geomechanical rock properties derived from analysis of full-wave sonic logs and core samples are combined to develop models to verify the brittleness and fracability indices. An improved understanding of the brittleness and fracability indices and reservoir mechanical properties is offered and valuable insight into the optimization of completion and hydraulic fracturing design is provided. The process of screening hydraulic fracturing candidates, selecting desirable hydraulic fracturing intervals, and identifying sweet spots within each prospect reservoir are demonstrated.
Agent-based models (ABMs) provide a fast alternative to traditional partial differential equation (PDE)- based oil reservoir models by applying localized inexpensive simulations, rather than solving a partial differential equation at every time-step. However, while there have been theoretical and numerical results obtained with ABMs in social science applications, the accuracy of ABMs has not been analyzed in the context of oil reservoir modeling.
Chen, Meiyi (College of Earth Science, Northeast Petroleum University) | Ji, Qingsheng (Exploration and Development Research Institute) | Chen, Shoutian (No.1 Geophysical Exploration Company of Daqing Drilling and Exploration Engineering Corporation) | Qin, Longpu (Exploration Department Daqing Oilfield Company Ltd) | Cong, Peihong (No.1 Geophysical Exploration Company of Daqing Drilling and Exploration Engineering Corporation)
Based on the seismic prediction difficulties of the tight sandstone reservoir in Fuyu formation in Zhaoyuan area, single-well sequence division and connecting-well sub-layer correlation are carried out according to logging and lithologic data, and short-cycle interface position is calibrated precisely after a mutual calibration of logging and seismic data. Horizon tracing in the whole area is also carried out to build highfrequency isochronous stratigraphic framework. On this basis, the log facies modes and the sedimentary facies of the short-cycles under a high-frequency isochronous stratigraphic framework are analyzed in the target area, sand-body geometric scale parameters and their relations and sand-body development degree are calculated out, and a sand-body geological model is also built out. According to the seismic data and layer-by-layer geological model of sand bodies, a spatial distribution probability model of facies-controlled sand bodies is built out, which is used to constrain the pre-stack seismic data in facies-controlled inversion calculation. Based on the results of facies-controlled inversion, the tight sandstone prediction is carried out. Finally, a method of isochronal facies-controlled pre-stack seismic inversion prediction of tight sandstone reservoir is formed and it realizes the effective prediction of superimposed sand bodies in target area. Compared with actual drilling results, the sandstone of more than 2m has clear depiction and the sandstone of between 1-2m also has response, which indicates that this method is feasible and practicable.
Arisandy, Mellinda (PETRONAS Carigali Indonesia Operations) | Mazied, Miftah (PETRONAS Carigali Indonesia Operations) | Putra, Bayu P (PETRONAS Carigali Indonesia Operations) | Yogapurana, Erik (PETRONAS Carigali Indonesia Operations) | B Mohd Idris, Jamin Jamil (PETRONAS Carigali Indonesia Operations) | Darmawan, Hendra I. (PETRONAS Carigali Kuala Lumpur)
This paper describes geochemistry analysis, hydrocarbon charge and entrapment model for prolific "MA" Block in the West Natuna Basin. Even though the area is currently at a mature exploration stage, the behaviour of hydrocarbon distribution in the area is still poorly understood and the link between discovered hydrocarbon and possible kitchens is still unknown. This study is an attempt to understand hydrocarbon expulsion, charging and entrapment in "MA" Block to de-risk further exploration efforts.
Several localized inverted half-grabens were identified through seismic interpretation. Nearby wells were then selected in evaluating source rock quality and maturity. In order to determine hydrocarbon expulsion model, 1D-3D burial history and thermal maturity models were constructed using integration of source rock and fluids geochemistry, temperature, seismic, and well data. Hydrocarbon charge and entrapment models were then simulated using 3D basin modeling software and calibrated with existing proven accumulation to produce a risked understanding of hydrocarbon distribution in the study area.
This study suggests that the most possible source rocks are the Late Eocene and Oligocene shales of Lama Formation and Lower Gabus Formations. Both source rocks are indicated by type I & type III kerogen. Lama source rock was confined in the initial grabens and post mature in deep paleo-grabens. This study confirmed that charging is derived from four (4) kitchen areas: Anoa, Gajah, Kakap, and Kambing grabens. The oil samples from "MA" Block indicated lacustrine facies. Rock geochemistry analysis portrayed oil-prone and gas-prone source rock.
In general, hydrocarbon was migrated from the southeastern area (Kambing graben) and southwestern area (Gajah graben). Hydrocarbon was later on accumulated in the nearest structural entrapments (anticlines). In the deep grabens (Kakap and Kambing), the hydrocarbon expulsion was starting as early as 37 Ma and 31 Ma, respectively, while in shallow graben (Anoa) the expulsion was starting at 29 Ma. The earliest structural trap commenced at 21 Ma, aligned with the initial compressional regime that was affecting the West Natuna Basin. Notable accumulative erosion in Miocene was nearly 1000 m at inverted structures, by which partly removed regional seal and reduced reservoir effectiveness. Significant yet-to-find hydrocarbon is predicted to be concentrated in the Anoa, Kakap, and Northeast Kambing area.